Northern States Power-Wisconsin (NSPW), a subsidiary of Xcel Energy (NYSE: XEL), plans to install a baghouse and activated carbon injection equipment for emissions on boilers #1 and #2 at its coal- and biomass-fired Bay Front plant in Ashland, Wisc.
NSPW applied Sept. 12 at the Wisconsin Public Service Commission for a Certificate of Authority on this $18.5m project. These new controls would reduce particulate matter and mercury emissions from boilers #1 and #2 and ensure NSPW achieves compliance with the U.S. Environmental Protection Agency’s National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. That rule is more commonly referred to as the Industrial Boiler MACT (IBMACT). The IBMACT requires affected sources to reduce emissions of several pollutants including particulate matter and mercury.
Using a combination of stack test and continuous emissions monitoring data, the company found that boilers #1 and #2 will not be able to meet the new IBMACT emissions limits with the current particulate matter control devices (electrified filter beds). The installation of the baghouses and the activated carbon injection systems, however, will ensure compliance with the emission limits in the March 2011 IBMACT and those in a December 2011 version of the proposed rule. The existing electrified filter bed particulate control systems on both boilers will be retired and partially removed as part of the construction project, the utility told the commission.
“It’s important to note that our evaluation of the new emission limits and the expected performance of the baghouses show the boilers may be able to meet the mercury limit in the IBMACT with only the new baghouses; but, the revised mercury limit in the December 2, 2011 proposal would be difficult, if not impossible, to meet without the addition of activated carbon injected into the flue gas stream,” the utility added.
Plant is old, smaller than it used to be and mostly fired with biomass
NSPW’s Bay Front plant is located on about 50 acres of land on the shores of Chequamegon Bay of Lake Superior in Ashland, Wisc. The plant originally began operation in 1916. By 1960, it operated five boilers and six turbines. Two of the boilers and three of the turbines have since been retired. The three remaining boilers feed into a combined steam header system that can support three turbine-generator sets.
These boilers, # 1, #2, and #5, burn a variety of fuels including coal, waste wood, railroad ties, tire-derived fuel and natural gas to produce steam that drives the three turbine generators. Of the remaining turbine/generator sets, #4 can produce 22 MW and came into service in 1949, #5 can produce 22 MW and came into service in 1952, and #6 can produce 30 MW and was placed in service in 1957.
Boilers #1 and #2 are Babcock and Wilcox spreader stoker, traveling grate boilers. Biomass is currently the primary fuel used in boilers #1 and #2. The new emissions project will involve installation of a pulse jet baghouse on boilers #1 and #2, as well as a compressed air system, ductwork and supports, and fly ash handling equipment. The activated carbon injection system will consist of a material storage silo, bin vent, rotary discharge valve and associated piping. By installing this new equipment, NSPW said it will be able to continue to use biomass as the primary fuel in these boilers. The vast majority of the biomass consumed in these boilers is obtained from local mills and harvesters within an 80-mile radius of the plant.
Installation activities for these new systems are scheduled for the winter of 2012-2013, with completion in March 2014.
Extended Bay Front life would provide needed grid support
In addition to ensuring NSPW meets the IBMACT requirements, the installation of the baghouse and activated carbon injection systems will allow the plant to continue to provide needed transmission voltage and system support in northern Wisconsin, NSPW wrote. The Bay Front plant, at its current rated and operating capacities, is needed to ensure transmission reliability for at least the next five to nine years, which is through the current expected life of the plant. It is unlikely that the Midwest ISO will allow the retirement of these boilers until the reliability concerns in the area are resolved or until other factors are addressed, including potential load growth expectations.
While the current life expectancy of the Bay Front plant is through 2021, the company said it is in the process of planning for a 15-year life extension, through 2036.
Currently, NSPW has received approval from the commission for, or has applied for approval of, $90m to $140m in transmission upgrades that will address some of the reliability issues. These upgrades will also help meet North American Electric Reliability Corp. (NERC) standards if any of the boilers at Bay Front were to be retired. An additional $80m to $100m of long term transmission investments will be needed, however, if load growth expectations continue to increase and to further ensure compliance with NERC standards if boilers #1 and #2 are retired, or more generally, if the Bay Front plant is retired, the company added.
These transmission projects could be constructed as early as 2018. However, due to recent experience with transmission projects that have been approved and constructed in western Wisconsin and the massive shifting of work forces that would be required to achieve the 2018 time frame, it is unlikely that all of the necessary projects could be built until the early to mid-2020s, NSPW said.
Utility says it also needs Bay Front to meet renewable portfolio needs
Unrelated to compliance with the IBMACT and the need for transmission support, is the contribution made by boilers #1 and #2 toward Wisconsin’s Renewable Portfolio Standard (RPS). Under current law, NSPW was required to establish a baseline percentage of retail sales generated from renewable energy resources based on the three-year average, from 2001 through 2003. By 2010, NSPW was required to and did increase its renewable component in retail sales by 2%. By 2015, NSPW is required to increase its renewable component of retail sales by an additional 4%. NSPW currently estimates that it will need to provide 12.89% of its retail sales from renewable energy to achieve compliance with the 2015 mandated threshold.
NSPW pointed out that it is not allowed to fall below the baseline, interim, or final RPS levels once the deadlines have passed. Thus, for example, between 2006 and 2010, NSPW could not fall below its baseline level of 6.89%, and between 2010 and 2015, it cannot fall below the interim threshold of 8.89%. In addition, if NSPW retires or mothballs a boiler or plant that contributed to the renewable baseline, it must replace the related lost renewable generation (in MWH) with other qualifying renewable generation before it could satisfy the 2006-2010 requirement, 2010 threshold, or work toward satisfying the 2015 mandated standard. Thus, if NSPW reduces the amount of renewable generation from Bay Front below the baseline level or below that level used to satisfy the 2010 threshold, it must make up that lost generation before it can work towards meeting the next RPS threshold.
In 2011, Bay Front accounted for about 16% of the renewable generation reported in the company’s annual RPS report. The most likely replacement renewable generation will be wind-based and located outside of Wisconsin due to access to better wind resources in the service territory of Northern States Power-Minnesota, NSPW said.
NSPW looked at other options besides the proposed emissions controls. Bay Front Boilers #1 and #2 have the capacity to burn natural gas and it is possible to burn 100% natural gas in both boilers. When burning 100% gas, however, each boiler’s rated capacity decreases significantly; from about 22 MW to about 6 MW. In addition, the company does not have the ability to cost effectively contract for firm natural gas deliveries to Bay Front.
The ability to burn natural gas was added to the boilers several years ago to help with boiler start-up and to increase generating capacity when burning another fuel such as coal or biomass. It is not possible to operate the boilers on natural gas at maximum load. Under this switch-to-gas scenario, the company would also need to obtain additional renewable generation from Minnesota-based wind facilities. While a qualifying renewable resource, wind generation is not dispatchable and would have to be shipped to Wisconsin through the transmission system, the utility noted. Also, the loss of about 32 MW of boiler capacity at the plant when switching to 100% gas would put the grid reliability in northern Wisconsin at risk, the utility said.